Article pubs.acs.org/EF
Gas Production from Methane Hydrates in a Dual Wellbore System Matilda Loh,† Jun Lin Too,† Simon Falser,†,‡ Praveen Linga,§ Boo Cheong Khoo,† and Andrew Palmer† †
Centre for Offshore Research and Engineering, Department of Civil and Environmental Engineering, and §Department of Chemical and Biomolecular Engineering, National University of Singapore, Singapore 117576, Singapore ABSTRACT: In a previous study using a single wellbore production system, it was demonstrated that a combination of depressurization and wellbore heating is more efficient than depressurization alone, where the endothermic dissociation process rapidly consumes the specific heat of the formation, leading to a sharp decrease in the dissociation rate. This study extends the work on gas production and explores the feasibility of a novel dual wellbore production scheme, where heating and depressurization are conducted on separate wellbores. The drawback with combining heating and depressurization on a single wellbore is that the produced fluids are flowing in an opposite direction to the heat from the wellbore, and this forced convection may slow the dissociation process. Gas production tests are carried out using the dual wellbore system with different combinations of pressure and temperature at the depressurization and heating wellbores, respectively. The ensuing experimental results showed that both increased depressurization and heating can lead to optimized gas production. A production scheme with a higher depressurization compared to a lower depressurization at the same wellbore heating is generally more energy-efficient, while a higher wellbore temperature at the same depressurization resulted in more gas produced but no improvement in efficiency. Although a dual wellbore scheme has been an established practice in the petroleum industry, this is likely to be the first employed in the hydrate gas production tests.
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Sikumi field test production in 2012 has shown that, by pumping mixed CO2−N2 liquid, methane gas is released, while CO2 hydrates are formed.19 There are several shortcomings in the single wellbore scheme employing both thermal stimulation and depressurization. A single wellbore scheme has to overcome forced convection and cooling caused by the fluid flowing back to the wellbore.1,12 The endothermic dissociation of hydrates also reduces the temperature, which may result in the reformation of hydrates at a constant pressure. In addition, as the dissociation front increases radially from the wellbore, there may exist the possibility of a decrease in the temperature gradient and an increase in the pressure gradient, which may lead to the hydrate reaching a stable phase and preventing the occurrence of further dissociation. On the other hand, forced convection improves the heat transfer within the dissociating region. This paper focuses on the separation of depressurization and heating into different wellbores, and in doing so, the forced convection through the pore fluid could be employed to supply energy into the dissociating region and, in turn, improve the efficiency of gas production.
INTRODUCTION Clathrate hydrates, more commonly referred to as gas hydrates, are solid crystalline compounds made up of water molecules and gas molecules, such as methane, ethane, CO2, etc.2,3 Found abundantly below the permafrost and deep-water sediments, they are the largest source of hydrocarbons in the world, with the potential to provide an enormous amount of natural gas for commercial consumption.4−8 Until now, there has been no commercial production of gas from methane hydrates worldwide, because research is still ongoing to find an efficient and economically feasible way of extraction. All of the production tests carried out have either been field or experimental tests.9−25 The first large-scale production tests have been conducted onshore at the Mallik site in Mackenzie Delta, Canada, in 2002,26−28 where hydrates were dissociated by thermal stimulation with hot water (70 °C). Only modest gas flow was achieved. In the second production tests carried out in 2008,29 the pressure of the hydrate-bearing layer was lowered using a perforated casing, where water was pumped out to depressurize the system. The hydrate was dissociated, and methane gas flowed out through the well. Production lasted for 7 days with sustained gas flow to the surface. It was concluded then that depressurization alone is a more efficient method of production. The most recent production tests were carried out in the Nankai Trough, Japan, in March 2013 and are possibly the world’s first offshore production tests, where hydrates were dissociated by depressurization in a 40 m zone in a radial manner. With this production test, Japan is targeting its first commercial production of methane hydrates in 2018. However, much still needs to be done before the world can consider methane hydrates for commercial use. Besides depressurization or thermal stimulation, the CO2/ CH4 exchange is believed to be yet another method.30−33 Ignik © 2014 American Chemical Society
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EXPERIMENTAL SETUP AND METHODOLOGY
A detailed description of the hydrate testing rig is provided in previous works.1,34 Briefly, the rig consists of a pressure vessel and an environmental chamber. The pressure vessel with a design pressure of 20 MPa can contain hydrate-bearing sediment with a size of 180 mm in diameter and 220 mm in height. Inside the pressure vessel, six thermocouples are fitted for temperature monitoring and wellbores are fitted for depressurization to simulate gas production. The Received: August 7, 2014 Revised: November 3, 2014 Published: November 4, 2014 35
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Figure 1. Location of thermocouples inside the pressure vessel. depressurization wellbore is connected to a spring-loaded regulator valve (for pressure control) and gravity separator before channeled into a water column displacement unit. The gravity separator is a small container with inlet and outlet located at the top to retain the pore fluid of the sample. The water column displacement has dimensions of 0.3 m in diameter and 2.5 m in height with a total volume of 176 L. The gas and water produced from the wellbore are passed through this gravity separator before the gas enters the displacement unit at the inlet, located at the top, which displaces water through the bottom outlet and measured on a balance.35 For this work, the testing apparatus was modified to incorporate two wellbores at 60 mm apart, namely, one for electrical heating and another for production of gas hydrate. The temperature at the heating wellbore is controlled electrically by a solid-state relay, with a 60 V direct current going into a 240 Ω, 15 W heater. Figure 1 and Table 1 show the location of the two
Table 1. Coordinates of the Location of Thermocouples Embedded in the Sample thermocouple
coordinates (x, y)
T1 T2 T3 T4 T5 T6
(−3, 0) (at heating wellbore) (3, 0) (at production wellbore) (−5, 1.5) (−1, −3) (0, 5.5) (14, 4)
Figure 2. Cross-section of the pressure vessel with the incorporated dual wellbores modified.
wellbores and six thermocouples. A thermocouple was placed on each of the wellbores, while the other four are spaced out between the two wellbores to lie between the different possible isotherms that could develop during the dissociation. All of the thermocouples are placed in a horizontal plane at half the height of the sample. Figure 2 shows the cross-sectional view of the hydrate rig. A pressure gauge is located at the top of the vessel to monitor the pressure of the system during the experiment. Throughout the test, the environmental temperature is kept constant by the circulation of monopropylene glycol around the vessel walls in an air-conditioned chamber. All of these are necessary to ensure that the temperature of the hydrate sample during testing is not affected by external heat fluxes. The gas and water that are produced from the wellbore are passed through a gravity separator, retaining the pore fluid of the sample, before the gas enters the water displacement unit at the inlet, located at the top, which displaces water through the bottom outlet and measured on a balance.35 Experimental Procedure. A more detailed description of the hydrate formation method is available from Falser et al.1 Briefly, the Toyura sand, with a particle diameter of 0.1−0.3 mm, is placed inside the pressure vessel. The pressure vessel is secured tightly and vacuumed to remove air trapped in voids. Methane gas is pressurized
into this vacuumed sample until the target pressure is achieved. The gas pressure depends upon the hydrate saturation required, which is calculated from Peng−Robinson’s equation.18 Water is pumped into the pressurized gas-rich sample up to 15 MPa, while the temperature is maintained at 3 °C throughout. The complete formation of methane hydrates takes an average of 65−70 h. Pressure drops occur throughout this period, and more water will be pumped to maintain the pressure at approximately 15 MPa. The completion of hydrate formation is indicated by the pressure staying constant (or declining by less than 0.1 MPa) and a constant temperature, signifying that there is no more free gas in the system. For seawater hydrate samples, the composition of the seawater is 1.67 wt % sodium chloride and 0.25 wt % sodium sulfate.34 The source of the seawater is taken off the east coast shores of Singapore. After the hydrates are formed, the production process begins by setting the heating wellbore to the test temperature (either +15 or +25 °C). Once the target temperature has been achieved, the other wellbore is depressurized to the desired pressure and then the production test is run for 90 min. The production time limitation is governed by the maximum amount of gas that can be stored in a water displacement unit with a capacity of 36
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176 L. There is minute fluctuation on the target pressure occurring during the whole production period.
recovered within the production period, with gas recovery factors over 80%. The time required would be much longer for cases 1 and 2 (production at 6 MPa) to recover approximately the same amount of gas. The combined pressure and temperature conditions that lead to a higher volume of produced gas may not necessarily be the most energy-efficient. It is possible that a production scheme that results in the greatest volume of gas may consume more energy to maintain dissociation, thereby leading to reduced energy efficiency. It is therefore essential to compare the amount of energy gained from the produced gas versus the amount of energy used during production for the various production tests. Because hydrate dissociation is an endothermic process, it requires an energy input to continue. This is provided in the form of the pumping energy to maintain the pressure during production, Ep, and the energy required for
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RESULTS AND DISCUSSION A total of seven heating/depressurization combinations were compared for the effect of the temperature, pressure, and salinity, as provided in Table 2: Table 2. Summary of Gas Production Test Cases test
hydrate medium
production setting
case 1
freshwater
P6 + T15
case 2
freshwater
P6 + T25
case 3
freshwater
P4 + T15
case 4
freshwater
P4 + T25
case 5 case 6
freshwater seawater
P4 P6 + T15
case 7
seawater
P5 + T25
remarks production at 6 MPa temperature at +15 production at 6 MPa temperature at +25 production at 4 MPa temperature at +15 production at 4 MPa temperature at +25 production at 4 MPa production at 6 MPa temperature at +15 production at 5 MPa temperature at +25
and °C and °C and °C and °C and and °C and °C
heating heating heating heating no heating heating heating
Gas Recovery Factor. The gas recovery factor was calculated using the following equation: gas recovery factor =
produced gas ηCH Vgas,stpTgas,stp/Tgas,init 4
where ηCH4 is the initial amount of methane gas based on the saturation, Vgas,stp is the volume of 1 mol of gas at standard temperature and pressure (22.4 L), Tgas,stp is the temperature of gas at standard temperature and pressure (273.15 K), and Tgas,init is the initial temperature of the gas (K). With the depressurization and heating from different wellbores simultaneously driving the dissociation, the water and gas volumes produced during the production tests are summarized in Table 3. The measured water displaced is converted into the volume of gas produced. The total volume of gas in the sample, Vtotal of gas in standard liters (SL), is found from the initial saturation.1 Almost all methane gas contained within the hydrates in cases 3 and 4 (production at 4 MPa) was
Figure 3. Comparison between production case 1 (6 MPa and +15 °C heating temperature) and case 2 (6 MPa and +25 °C heating temperature). Pore pressure development is shown at the top, while corresponding gas volume collected is shown at the bottom.
Table 3. Results for the Gas Production Test of Freshwater and Seawater Hydrates
a
test
case 1
case 2
case 3
case 4
case 5
case 6
case 7
total sample volume (SL) total sand weight (kg) porosity (%) initial CH4 gas pressure (MPa) hydrate saturationa (%) water produced (SL) gas produced (SL) Vtotal of gas contained (SL) gas recovery factor (%) Ep (kJ) Eh (kJ) energy yield (kJ) net energy gained (kJ) net energy gained (%)
5.62 8.91 39.8 6.59 40.0 0.76 64.7 145.8 44.9 −636 −68 2569 1865 72.6
5.62 8.95 39.5 6.67 40.0 0.60 74.7 144.3 52.2 −636 −180 2963 2147 72.5
5.62 8.74 40.9 6.61 40.0 0.40 143.4 146.3 98.3 −965 −68 5690 4657 82.5
5.62 8.77 41.4 6.60 40.0 0.84 133.9 159.8 84.3 −965 −180 5313 4168 78.4
5.62 8.99 39.2 6.61 40.0 1.52 85.5 144.8 59.0 −965 0 3391 2426 71.5
5.62 9.03 39.0 6.70 40.0 3.6 55 152.2 38.5 −636 −68 2182 1478 67.7
5.62 8.93 39.6 6.70 40.0 0.82 122.48 134.6 91.6 −965 −180 4860 4044 83.2
The hydrate saturation is calculated from Peng−Robinson’s equation as presented by Priest et al.18 37
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Figure 4. Comparison between production case 3 (4 MPa and +15 °C heating temperature), case 4 (4 MPa and +25 °C heating temperature), and case 5 (4 MPa). Pore pressure development is shown at the top, while corresponding gas volume collected is shown at the bottom.
Figure 6. Pore pressure development (top) with different production pressures of case 4 (4 MPa and +25 °C heating temperature) and case 2 (6 MPa and +25 °C heating temperature) and the corresponding gas volume collected (bottom).
Figure 7. Comparison of the recovery factor and net energy between freshwater and seawater methane hydrates.
10 °C difference in temperature has in essence been used in the forced convection process. It can be inferred that depressurization to a lower wellbore pressure (at the same temperature) at 4 MPa compared to 6 MPa results in a higher energy yield as well as net energy gained, with a higher efficiency. Taking the three tests of 4 MPa production pressure into consideration (cases 3−5), the addition of heat (cases 3 and 4) increases both the energy yield and efficiency compared to the sole depressurization (case 5); the larger temperature gradient between the two wellbores increases the convection and dissociation drive. Effect of the Temperature. Figure 3 shows the pressure− time histories at the production wellbore and the corresponding volume of gas collected for cases 1 and 2, where the production pressure was 6 MPa and the temperature increase was 15 and 25 °C, respectively. The pressure at the production wellbore was maintained as constant as possible, at 4 or 6 MPa for the respective test conditions, as the volume of gas produced/collected increased. An intermittent sudden increase in gas produced throughout the production tests was
Figure 5. Pore pressure development (top) with different production pressures of case 3 (4 MPa and +15 °C heating temperature) and case 1 (6 MPa and +15 °C heating temperature) and the corresponding gas volume collected (bottom).
heating, Eh. The energy gain would come from the produced gas, which can be acquired from the calorific value of methane at 39.68 kJ/SL. The method used to compute the input energy Ep and Eh is adapted from that of our previous work on a single wellbore scheme.1 In comparison of cases 1 and 2, at a higher production pressure of 6 MPa, increasing the temperature from 15 to 25 °C increases the energy yield by 400 kJ but does not improve energy efficiency, because the net energy gained remains the same at 72%. The additional heat energy from the 38
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for case 2. This was probably due to the initial depressurization rate for case 1, which was considerably higher compared to that for case 2, as seen in the production wellbore pressure−time history plots before t = 0. Subsequently, the production rate for case 2 with a higher heating wellbore temperature is greater than that for case 1. The temperature increase of 10 °C has essentially produced a 13% increase in the volume of gas produced at the end of the 90 min production run. The results for the cases with pressure of 4 MPa bottom hole pressure (BHP) at the production wellbore with various heating temperatures at the heating wellbore (cases 3−5) are as shown in Figure 4. Again, the slight pressure fluctuations particularly at the 35th and 62nd minute for cases 4 and 3, respectively, were due to adjustment made to maintain the production pressure at 4 MPa. The result is that the gas produced for case 3 is higher than that for case 4 at the end of the 90 min production. However, it is expected that case 4 would yield higher gas production similar to case 2 because the heating temperature is higher for these two cases, as compared to cases 1 and 3. Effect of the Pressure. Figures 5 and 6 present the production pressures of 4 and 6 MPa with heating to 15 and 25 °C, respectively. It is evident from these figures that differences in production wellbore pressure give rise to a larger difference than the temperature effect. In comparison of case 3 to case 1, a production pressure difference of 2 MPa has
sometimes observed and attributed largely to adjustments to the pressure regulator to maintain the production pressure. The initial production rate (gradient of the volume of gas produced−time history plots) for case 1 was faster than that
Figure 8. Schematic of forced convection during dissociation.
Figure 9. Temperature histories of case 5 (4 MPa), case 3 (4 MPa and +15 °C heating temperature), and case 4 (4 MPa and +25 °C heating temperature) . The dashed line in each panel represents the equilibrium temperature of methane hydrates, Teqm. 39
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Figure 10. Temperature histories of case 1 (6 MPa and +15 °C heating temperature) and case 2 (6 MPa and +25 °C heating temperature). The dashed line in each panel represents the equilibrium temperature of methane hydrates, Teqm.
increased the gas produced up to 2.22 times. This is similar for comparison between cases 4 and 2, whereby gas produced is 1.79 times. A 2 MPa reduction in the production pressure has significantly increased the volume of gas produced. The difference of 2 MPa corresponds to around 200 m of depth of water, and the increased pressure gradient could improve the efficiency of production within the same given production time. Effect of Freshwater versus Seawater. The phase equilibrium data for seawater and methane hydrates in the presence of Toyoura sand show a temperature offset of about 0.9 K for the experimental conditions employed in this work.34 This would suggest that, with an offset of 0.9 K, the energy required to dissociate hydrates under the same wellbore pressure and temperature conditions would be comparable. From Figure 7, it can be seen that the recovery factor and net energy for freshwater hydrates are both slightly above that of seawater hydrates. The effects of wellbore heating on the production of seawater hydrates are similar to those for freshwater. From Table 3 (case 6), the quantity of gas produced was 55 L for seawater hydrate, which was slightly less than that for freshwater hydrate at 64 L. For case 7, the target production pressure was 6 MPa with a heating temperature of 25 °C. However, the adjustment made to the needle valve had lowered the depressurization to 5 MPa over the production period while maintaining the heating temperature. This has resulted in 122 L of gas produced, which was 2.2 times that of case 6 and 1.6 times that of case 2 (freshwater). Such a drop in bottom hole pressure has led to the observed difference in the amount of gas produced in case 7, with all other conditions being consistent with case 2.
Figure 11. Temperature differences at the heating and production.
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FORCED CONVECTION AND DISSOCIATION DRIVE One of the attractions of a dual wellbore system is employing the forced convection caused by the heating wellbore to transmit heat through the pore fluid into the dissociating zone at the other wellbore, thereby giving rise to an increased production. During the dissociation, the simultaneous heating and depressurization on the separate wellbores results in two dissociation fronts, as illustrated in Figure 8. In addition, the temperature gradient between the two wellbores has some contribution in inducing the warmer pore fluid to flow from the 40
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Figure 12. Comparison of the recovery factor and net energy gain with the single wellbore scheme.
combination of depressurization and heating on separate wellbores increases the gas recovery further by 5% and has a higher net energy gain of almost 10% compared to the single wellbore system, as shown in Figure 12. The advantageous use of forced convection to drive more energy into the dissociating zone makes the dual wellbore system an improved method of extracting gas from the methane hydrates. The effects of a dual wellbore system might be even more pronounced in a field test. This is because it is much easier for the produced fluids to flow toward the production wellbore after having been dissociated by the heating wellbore at a distance away and they are moving with the natural heat flow. In a single wellbore system in the field, the produced fluids would be flowing against the dissipating heat from the same wellbore and the thermal stimulation may not be fully used to improve the dissociation.
heating wellbore toward the depressurization wellbore and further increases the dissociation in this said region. The most straightforward and logical way to explain the variation in the forced convection is by observing the volume of gas produced for the different combinations of production wellbore pressure and heating wellbore temperature. This is illustrated using the temperature histories of the various tests. Figures 9 and 10 show the change in the temperature recorded by the thermocouples during the 90 min production period for freshwater sample depressurization to 4 and 6 MPa bottom hole pressure conditions. The equilibrium temperatures, Teqm, in the figures are calculated using the empirical phase boundary equation described by Loh et al. and the pressure−time histories shown in Figures 5 and 6.34 For the sample subjected to depressurization alone with no heating, as in case 5, the main dissociation drive was the pressure reduction from formation pressure (approximately 15 MPa at the initial starting point) to 4 MPa; this led to the difference between the equilibrium temperature and sediment temperature being at a maximum of 2 K. In such a scenario, the only energy used for hydrate dissociation came from depressurization, while thermal stimulation from the heating wellbore was not employed. For case 3, there is a significantly higher temperature gradient than case 5, hence giving rise to a higher dissociation drive. To compare the production scenarios of cases 3 and 4, the temperature gradient is used. When the production pressure was 4 MPa, this resulted in an equilibrium temperature of 4.5 °C, as calculated from the phase boundary equation.34 As seen in Figure 11, the temperature gradient between the two wellbores, dT, is significantly steeper for wellbore heating at 25 °C than at 15 °C; this gives rise to a greater convection and heat transfer from the heating wellbore to the production wellbore. With a higher energy drive transferring more heat into the dissociating zone, this explains why case 4 would technically enable a higher recovery of gas produced than case 3. The results are similar for cases 1 and 2.
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CONCLUSION In this paper, the key findings from dual wellbore production are summarized as follows: (1) In comparison to the single wellbore system, the simultaneous heating and depressurization in a dual wellbore system results in two dissociation fronts. With a larger dissociation drive, the net energy gain increased by almost 10%. (2) For the dual wellbore system, the effect of pressure yields higher production of gas. Production at 4 MPa yielded nearly twice as much as production at 6 MPa. (3) For the dual wellbore system, the effect of the temperature drives more dissociation by increasing the temperature gradient between the two wellbores. (4) Gas recovery for freshwater and seawater only differed slightly. This is expected because the phase boundaries for freshwater and seawater hydrates have only an offset of 0.9 K, while the dissociation enthalpy remains constant.
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AUTHOR INFORMATION
Present Address
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‡
Simon Falser: Shell (China) Project and Technology, Beijing 100004, People’s Republic of China.
DUAL WELLBORE VERSUS SINGLE WELLBORE SYSTEM It was previously established that a combination of depressurizing and heating is a more efficient production scheme than just depressurization alone.1 This is confirmed by the following set of experiments as well; a depressurization to 4 MPa recovers a lesser volume of gas compared to depressurization to 4 MPa and heating from 15 and 25 °C (Table 3). However, under the same depressurizing and heating conditions, production with a
Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors thank the Ministry of Education’s Academic Research Fund (AcRF) Tier 1 (R-279-000-386-112) and the National University of Singapore (R-279-000-420-750) for financial support. 41
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dx.doi.org/10.1021/ef501769r | Energy Fuels 2015, 29, 35−42
